Control for rotary steerable system

ABSTRACT

Angular position readings are obtained during rotation of an apparatus in a borehole, and angular rate readings are obtained over time of the rotation. The angular rate readings are adjusted based at least on the angular position readings. The angular position measurement does not require calibrated magnetometers or accelerometers to function. Additionally, a dynamic scale factor calculation for an angular rate gyroscope (ARG) allows the ARG to be used over a much wider operating range than without such a calculation. Finally, an integrated angular rate from the ARG calibrated for bias and scale factor fills in positional information between the magnetometers&#39; zero crossings to deliver a high resolution hybrid angular position system capable of measuring precise angular position at high and irregular downhole rotation rates.

CROSS-REFERENCE TO RELATED APPLICATIONS

This is a continuation of U.S. application Ser. No. 15/282,379 filed 30Sep. 2016, which was filed concurrently with U.S. application Ser. No.15/282,242 entitled “Rotary Steerable System Having Multiple IndependentActuators,” both of which are incorporated herein by reference in itsentirety.

FIELD OF THE DISCLOSURE

The subject matter of the present disclosure relates to an apparatus andmethod for controlling a downhole assembly. The subject matter is likelyto find its greatest utility in controlling a steering mechanism of adownhole assembly to steer a drill bit in a chosen direction, and mostof the following description will relate to steering applications. Itwill be understood, however, that the disclosed subject matter may beused to control other parts of a downhole assembly.

BACKGROUND OF THE DISCLOSURE

When drilling for oil and gas, it is desirable to maintain maximumcontrol over the drilling operation, even when the drilling operationmay be several kilometers below the surface. Steerable drill bits can beused for directional drilling and are often used when drilling complexborehole trajectories that require accurate control of the path of thedrill bit during the drilling operation.

Directional drilling is complicated because the steerable drill bit mustoperate in harsh borehole conditions. The steering mechanism istypically disposed near the drill bit, and the desired real-timedirectional control of the steering mechanism is remotely controlledfrom the surface. Regardless of its depth within the borehole, thesteering mechanism must maintain the desired path and direction and mustalso maintain practical drilling speeds. Finally, the steering mechanismmust reliably operate under exceptional heat, pressure, and vibrationconditions that will typically be encountered during the drillingoperation.

Many types of steering mechanism are used in the industry. A common typeof steering mechanism has a motor disposed in a housing with alongitudinal axis that is offset or displaced from the axis of theborehole. The motor can be of a variety of types including electric andhydraulic. Hydraulic motors that operate using the circulating drillingfluid are commonly known as a “mud” motors.

The laterally offset motor housing, commonly referred to as a benthousing or “bent sub”, provides lateral displacement that can be used tochange the trajectory of the borehole. By rotating the drill bit withthe motor and simultaneously rotating the motor housing with thedrillstring, the orientation of the housing offset continuously changes,and the path of the advancing borehole is maintained substantiallyparallel to the axis of the drillstring. By only rotating the drill bitwith the motor without rotating the drillstring, the path of theborehole is deviated from the axis of the non-rotating drillstring inthe direction of the offset on the bent housing.

Another steering mechanism is a rotary steerable tool that allows thedrill bit to be moved in any chosen direction. In this way, thedirection (and degree) of curvature of the borehole can be determinedduring the drilling operation, and can be chosen based on the measureddrilling conditions at a particular borehole depth. Rotary steerabletools can be configured as point-the-bit or push-the-bit to steerdrilling.

Typically, the rotary steerable tool uses a reference to the tool'sposition while drilling so the rotary steerable tool can steer theadvancing borehole in the correct direction. Because the rotarysteerable tool rotates in the advancing borehole and experiences anumber of disturbances in the process, the rotational speed of the toolcan vary significantly over the course of several and even a singlerotation. For example, Stick-Slip is one type of variation that canoccur in the rotational speed of the steering apparatus. Stick-Slip canproduce inaccuracies that cause significant difficulties in controllingthe trajectory of the borehole. Therefore, accurate sensing capabilitiesof the rotary steerable tool in high resolution is beneficial to systemperformance, allowing the rotary steerable tool to better compensate fordownhole dynamics.

Although several rotary steerable tools available in the industry may beeffective, they may still suffer from inaccurate operation due to thedynamic conditions that can occur downhole while advancing a borehole.

SUMMARY OF THE DISCLOSURE

According to the present disclosure, a method is used in drilling aborehole with an apparatus having at least one actuator for steering.The borehole is advanced by imparting rotation to the apparatus. Angularrate readings of the rotation are obtained, and angular positionreadings of the apparatus are obtained during the rotation.

The angular rate readings are adjusted based at least on the angularposition readings to determine angular positions of the apparatus.Actuations of the at least one actuator is determined for steering theapparatus toward a target toolface relative to the determined angularpositions. The apparatus can then be deviated in the advancing boreholein response to the determined actuations of the at least one actuator.

According to the present disclosure, an apparatus is imparted withrotation for drilling a borehole. The apparatus comprises at least oneactuator, a sensing element, and a control system. The at least oneactuator is actuatable to steer the apparatus in advancing the borehole.During the rotation of the apparatus, the sensing element obtainsangular position readings and obtains angular rate readings of therotation.

The control system is in operable communication with the at least oneactuator and the sensing element. Using the obtained readings to controlthe apparatus, the control system adjusts the angular rate readingsbased at least on the angular position readings to determine angularpositions of the apparatus, determines actuations of the at least oneactuator for steering the apparatus toward a target direction relativeto the determined angular positions, and deviates the apparatus inadvancing the borehole in response to the determined actuations of theat least one actuator.

The disclosed method and apparatus of the present disclosure may bedirected to a push-the-bit configuration of steering. In push-the-bit,the drilling direction of the drill bit in a desired direction ischanged by pushing against the side of the borehole in an opposingdirection. Comparable components and techniques disclosed herein can beused in the other type of steering configuration of point-the-bit. Inthe point-the-bit configuration, the drilling direction of the bit in adesired direction is changed by pushing an internal drive shaft havingthe drill bit in the desired direction. As such, the components andtechniques disclosed herein with respect to the push-the-bit system canapply equally well to a point-the-bit system through a reversal ofpushing components from external (push) to internal (point).

In the disclosed method and apparatus, toolface offset readings of theapparatus in the borehole can be obtained at least periodically when notrotating. The angular position readings of the apparatus can then becorrected relative to the at least periodically obtained toolface offsetreadings. Further, the angular rate readings can be adjusted based atleast on the angular position readings corrected relative to the atleast periodically obtained toolface offset readings.

To at least periodically obtain the toolface offset readings of theapparatus in the borehole when not rotating, a determination can be madethat the apparatus is not rotating. A magnetic toolface (e.g., using X-Ymagnetometer readings) and a highside toolface (e.g., usingaccelerometer readings) are obtained of the apparatus when not rotating,and the toolface offset is calculated from the determined magnetictoolface and highside tool face. This calculated toolface offset can beadjusted by at least one dynamic parameter based on information ofinclination and azimuth of the apparatus.

To obtain the angular position readings of the apparatus during therotation, a calculation is made for each of one or more states of theangular position readings in two orthogonal axes to find a resolvedangular orientation corrected by a toolface offset. For example, thecalculations can detect zero-crossings for X-Y directions of the angularposition readings at four of the states in each of the X-Y directions.In turn, the angular rate readings accumulated over time can be adjustedby the resolved angular orientations.

Calibrations can be performed for the sensor readings. In general, atleast drilling parameter downhole (e.g., temperature, mud flow rate, mudweight, etc.) can be measured so that the angular position readingsand/or the angular rate readings can be adjusted based on themeasurement. Bias of the angular rate readings can be measured at leastperiodically when the apparatus is not rotating in the borehole, and theangular rate readings obtained during the rotation can be adjusted bythe at least periodically measured bias. The angular rate readings canalso be calibrated for temperature effects based on a scale factordetermined dynamically from the obtained angular position readings.Further, the angular position readings obtained during the rotation canbe calibrated based on at least one of: sensor bias, scale of first ofthe readings with respect to a first axis relative to second of thereadings with respect to a second axis, and a misalignment of the firstand second axes relative the apparatus.

For the steering, the actuations of the at least one actuator determinedduring the rotation can involve determine a first angular orientation tostart the actuation and a second angular orientation to stop theactuation for each of the at least one actuator. The actuations of theat least one actuator can be monitored so that adjustments to theactuations can be made in response to the monitoring.

Although suited for steering during directional drilling, teachings ofthe present disclosure can be used in other implementations, such as inmeasurement-while-drilling (MWD) or logging-while-drilling (LWD)implementations. For instance, the teachings of the present disclosurecan be used when measuring/logging with at least one sensor on anapparatus in a borehole. In this technique, the at least one sensoradvances in the borehole while rotation is imparted to the apparatus sothat the at least one sensor senses measurements while rotation isimparted to the apparatus advancing in the borehole. Angular ratereadings are obtained of the rotation of the apparatus, and angularposition readings are obtained of the apparatus during the rotation. Thetechnique adjusts the angular rate readings based at least on theangular position readings to determine angular positions of theapparatus.

In this way, one or more the measurements of the at least one sensorsensing during the rotation can be correlated to the determined angularpositions. In turn, an image can be generated from the one or morecorrelated measurements. The results can give high resolution angularposition measurements that can improve the quality of log images,wellbore surveys, and the like. Also, the correlation can allow fortargeted sensing by the at least one sensor. For instance, the one ormore measurements sensed with the at least one sensor at one or moresensed directions during the rotation can be correlated to one or moretarget directions of the determined angular positions. The result isthat the at least one sensor can sense towards (or be correlated to) oneor more target directions based on the determined angular positions.

Briefly, there are a number of benefits of the teachings of the presentdisclosure. In one benefit, the angular position measurement does notrequire “calibrated sensors,” such as magnetometers or accelerometers. A“calibrated sensor” typically means that, during tool production andsubsequent testing activities, the tool's sensor is subjected to aseries of mechanical orientations at various temperatures during whichdata is collected. This raw data is then post-processed to generate aformal set of calibration coefficients, which are then typically loadedinto the tool's memory so that they are directly available to the sensorcompensation algorithms that execute during tool deployment. Oneadvantage of the techniques in the present disclosure is that thetechniques potentially eliminate the requirement to characterize thesensor using these traditional methods. Instead, the present techniquesdynamically generate sensor calibration coefficients in the form of‘bias’ and ‘scale factor’ corrections during deployment.

As an additional benefit, a dynamic scale factor calculation for anangular rate gyroscope (ARG) allows the gyroscope to be used over a muchwider operating range than without such a calculation. Finally, anintegrated angular rate from the gyroscope calibrated for bias and scalefactor fills in positional information between magnetometers' zerocrossings to deliver a high resolution hybrid angular position system,which is capable of measuring precise angular position at high andirregular downhole rotation rates. These and other benefits will beevident from the present disclosure.

The foregoing summary is not intended to summarize each potentialembodiment or every aspect of the present disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 schematically illustrates a downhole assembly incorporating asteering apparatus according to the present disclosure.

FIG. 2 schematically illustrates a configuration of a steering apparatusaccording to the present disclosure.

FIGS. 3A-3B schematically illustrate end views of the steering apparatusduring operation.

FIGS. 4A-4B plot examples of stick slip under consideration according tothe present disclosure.

FIGS. 5A-5B plot examples of high frequency torsional oscillation underconsideration according to the present disclosure.

FIG. 6 illustrates a schematic of a control system for the disclosedsteering apparatus.

FIG. 7 illustrates a flow diagram of the control techniques for thedisclosed steering apparatus.

FIG. 8 plots bias and sensitivity of an angular rate sensor relative totemperature.

DETAILED DESCRIPTION OF THE DISCLOSURE

FIG. 1 schematically illustrates a drilling system 10 incorporating arotating steering apparatus 50 according to the present disclosure. Asshown, a downhole drilling assembly 20 drills a borehole 12 penetratingan earth formation 11. The assembly 20 is operationally connected to adrillstring 22 using a suitable connector 21. In turn, the drillstring22 is operationally connected to a rotary drilling rig 24 or other knowntype of surface drive.

The downhole assembly 20 includes a control assembly 30 having a sensorsection 32, a power supply section 34, an electronics section 36, and adownhole telemetry section 38. The sensor section 32 has various sensingelements, such as directional sensors, accelerometers, magnetometers,and inclinometers, which can be used to indicate the orientation,movement, and other parameters of the downhole assembly 20 within theborehole 12. This information, in turn, can be used to define theborehole's trajectory for steering purposes. The sensor section 32 canalso have any other type of sensors used in Measurement-While-Drilling(MWD) and Logging-While-Drilling (LWD) operations including, but notlimited to, sensors responsive to gamma radiation, neutron radiation,and electromagnetic fields.

The electronics section 36 has electronic circuitry to operate andcontrol other elements within the downhole assembly 20. For example, theelectronics section 46 has downhole processor(s) (not shown) anddownhole memory (not shown). The memory can store directional drillingparameters, measurements made with the sensor section 32, anddirectional drilling operating systems. The downhole processor(s) canprocess the measurement data and telemetry data for the various purposesdisclosed herein.

Elements within the downhole assembly 20 communicate with surfaceequipment 28 using the downhole telemetry section 38. Components of thistelemetry section 38 receive and transmit data to an uphole telemetryunit (not shown) within the surface equipment 28. Various types ofborehole telemetry systems can be used, including mud pulse systems, mudsiren systems, electromagnetic systems, angular velocity encoding, andacoustic systems.

The power supply section 34 supplies electrical power necessary tooperate the other elements within the assembly 20. The power istypically supplied by batteries, but the batteries can be supplementedby power extracted from the drilling fluid by way of a power turbine,for example.

During operation, a drill bit 40 is rotated, as conceptually illustratedby the arrow RB. The rotation of the drill bit 40 is imparted byrotation RD of the drillstring 22 at the rotary rig 24. The speed (RPM)of the drillstring rotation RD is typically controlled from the surfaceusing the surface equipment 28. Additional rotation to the drill bit 40can also be imparted by a drilling motor (not shown) on the drillingassembly 20.

During operation, the drilling fluid system or pumps 26 pumps drillingfluid or “mud” from the surface downward and through the drillstring 22to the downhole assembly 20. The mud exits through the drill bit 40 andreturns to the surface via the borehole annulus. Circulation isillustrated conceptually by the arrows 14.

The steering apparatus 50 rotates with the drill string 22 in impartingrotation to the drill bit 40. To directionally drill the advancingborehole 12 with the downhole assembly 20, a control system orcontroller 60 operates, actuates, activates, etc. one or moredirectional devices 70 a-c on the apparatus 50. Preferably, multipledevices 70 a-c can be operated independently on the apparatus 50, andthe control system 60 can operate the devices 70 a-c individually usinghydraulic, mechanical, and other configurations. For the hydraulicconfiguration, the control system 60 changes delivery of a portion ofthe flow of the fluid (circulated drilling mud) to actuate the devices70 a-c, and the control system 60 in the mechanical configurationchanges physical engagement to actuate the devices 70 a-c. Theindependent operation of the multiple directional devices 70 a-c altersthe direction of the steering apparatus 50 as it advances the borehole12. To direct the trajectory of the advancing borehole 12, the controlsystem 60 uses orientation information measured by the sensor section 32cooperating with control information stored in the downhole memory ofthe electronics section 36.

The independent extension/retraction of the directional devices 70 a-ccan be coordinated with the orientation of the drilling assembly 20 inthe advancing borehole 12 to control the trajectory of drilling. In theend, the extension/retraction of the directional devices 70 a-cdisproportionately engages the drill bit 40 against a certain side inthe advancing borehole 12 for directional drilling. (Reference todisproportionate engagement at least means that the engagement inadvancing the borehole 12 is periodic, varied, repetitive, selective,modulated, changing over time, etc.)

Given the above description of the drilling system 10, discussion nowturns to embodiments of the drilling assembly 20 having the steeringapparatus 50 to achieve directional drilling.

A hydraulic configuration of the steering apparatus 50 is schematicallyshown in more detail in FIG. 2. The controller 60 connects to thecontrol assembly 30 having the sensor section 32, the power source 34,etc. The controller 60 also connects to each of the one or moredirectional devices or directors 70. (Two directional devices 70 a-b areschematically shown here for illustrative purposes: the apparatus 50 canhave more or less as desired.) Each directional device 70 a-b includesan actuator 72 and a movable element 76 disposed on the apparatus 50 torotate therewith. Each device 70 a-c is independently operable to moveits movable element 76 between an extended condition and a retractedcondition relative to the apparatus 50.

Various devices can be used for the actuator 72, such as hydraulicvalves, electric motors, solenoids, and the like. Likewise, variousdevices can be used for the movable element 76, such as pistons, pads,arms, and the like. In one particular arrangement, for example, theactuators 72 include hydraulic components to direct a portion of boreflow (15) (passing through the apparatus 50 from the drill string (22)to the drill bit (40)) to piston chambers 74 having pistons as themovable elements 76. Diverted flow (17) from the actuators 72 canactivate these pistons as the movable elements 76 in the piston chambers74 to move pads 78 to engage the borehole as the apparatus rotates.Expelled fluid (19) from the piston chambers 74 by the actuators 72 canthen allow the pads 78 to retract from the borehole as the apparatus 50rotates. As will be appreciated, other actuators 72 and moveableelements 76 can be used to achieve similar actuations and can rely onhydraulics, mechanical engagement, electric power, or other motivesource.

By independently operating the multiple directional devices 70 a-b, thesteering apparatus 50 steers the assembly (20) using active deflectionas the apparatus 50 rotates with the drill string (22). Therefore, thesteering apparatus 50 of FIG. 2 operates to steer drilling duringrotation R about the apparatus' axis A. This rotation R of the apparatus50 can average 300-rpm or more. Each actuator 72 can be operated toextend its piston as the movable elements 76 at the same targetposition, synchronous to the apparatus' rotation R. Meanwhile, therotary position of the apparatus 50 is determined by the sensor section32 and the like of the control system 30 (discussed in more detaillater).

Having an understanding of the steering apparatus 50, discussion nowturns to its operation. FIGS. 3A-3B schematically illustrate end viewsof the steering apparatus 50 during operation in two states ofoperation. As noted herein, the steering apparatus 50 has one or moredirectional devices 70 a-c disposed around the apparatus' housing 51,such as the three directional devices 70 a-c depicted here. As alsonoted herein, the apparatus 50 is capable of controlling multipleactuators (not shown) independently to extend the directional devices 70a-c as they rotate with the housing 51.

As expressed herein, the housing 51 having the directional devices 70a-c rotates with the drillstring (22), and the housing 51 impartsrotation to the drill bit (40). As these components rotate, thetransverse displacement of the directional devices 70 a-c can thendisplace the longitudinal axis of the housing 51 relative to theadvancing borehole. This, in turn, tends to change the trajectory of theadvancing borehole. To do this, the independent extensions/retractionsof the directional devices 70 a-c are timed relative to a desireddirection D to deviate the apparatus 50 during drilling. In this way,the apparatus 50 operates to push the drill bit (40) to change thedrilling trajectory.

FIGS. 3A-3B show one of the movable directional devices 70 a extendedtherefrom during a first rotary orientation (FIG. 3A) and then during alater rotary orientation (FIG. 3B) after the housing 51 has rotated.Because the steering apparatus 50 is rotated along with the drillstring(22), the operation of the steering apparatus 50 is cyclical tosubstantially match the period of rotation of the drillstring (22).

As the steering apparatus 50 rotates, for instance, the orientation ofthe directional devices 70 a-c is determined by the control system (60),position sensors, toolface (TF), etc. When it is desired to deviate thedrill bit (40) in the desired direction D, then it is necessary toextend one or more of the directional devices 70 a-c as they face towardthe opposite direction O. The control system (60) calculates theorientation of the diametrically opposed position O and instructs theactuators for the directional devices 70 a-c to operate accordingly.Specifically, the control system (60) may produce the actuation so thatone directional device 70 a extends at a first angular orientation (a inFIG. 3A) relative to the desired direction D and then retracts at asecond angular orientation (β in FIG. 3B) in the rotation R of thesteering apparatus 50.

Because the directional device 70 a is rotating in direction R with thehousing 51, orientation of the directional device 70 a relative to areference point is determined using the toolface (TF) of the housing 51.This thereby corresponds to the directional device 70 a being actuatedto extend starting at a first angular orientation θ_(A) relative to thetoolface (TF) and to retract at a second angular orientation θ_(B)relative to the toolface (TF). The toolface (TF) of the housing 51 canbe determined by the control system (60) using the sensors andtechniques discussed below.

Because the directional device 70 a does not move instantaneously to itsextended condition, it may be necessary that the active deflectionfunctions before the directional device 70 a reaches the oppositeposition O and that the active deflection remains active for aproportion of each rotation R. Thus, the directional device 70 a can beextended during a segment or width S of the rotation R best suited forthe directional device 70 a to extend and retract relative to thehousing 51 and engage the borehole to deflect the housing 51. The RPM ofthe housing's rotation R, the drilling direction D relative to thetoolface (TF), the operating metrics of the directional device 70 a, andother factors involved can be used to define the segment S. If desired,it can be arranged that the angles α and β are equally-spaced to eitherside of the position O, but because it is likely that the directionaldevice 70 a will extend gradually (and in particular more slowly than itwill retract) it may be preferable that the angle β is closer to theposition O than is the angle α.

Of course, the steering apparatus 50 as disclosed herein has theadditional directional devices 70 b-c arranged at different angularorientations about the housing's circumference. Extension and retractionof these additional directional devices 70 b-c can be comparablycontrolled in conjunction with what has been discussed above withreference to FIGS. 3A-3B so that the control system (60) can coordinatemultiple retractions and extensions of the serval directional devices 70a-c during each of (or one or more of) the rotations R. Thus, thedisplacement of the housing 51 and directional devices 70 a-c can betimed with the rotation R of the drillstring (22) and the apparatus 50based on the orientation of the steering apparatus 50 in the advancingborehole. The displacement can ultimately be timed to direct the drillbit (40) in a desired drilling direction D and can be performed witheach rotation or any subset of the rotations.

As noted previously, the steering apparatus 50 uses a reference to theapparatus' angular position while drilling so the steering apparatus 50can steer the advancing borehole in the correct direction. Because thesteering apparatus 50 rotates in the advancing borehole and experiencesa number of disturbances in the process, the rotational speed of theapparatus 50 can vary significantly over the course of several and evena single rotation. For example, stick-slip is one type of disturbancethat can occur in the rotational speed of the steering apparatus 50.Stick-slip of the bottom hole assembly can produce inaccuracies thatcause significant difficulties in controlling the trajectory of theborehole. Therefore, accurate angular position of the steering apparatus50 in high resolution is beneficial to system performance, allowing thesteering apparatus 50 to better compensate for downhole dynamics. Tothat end, features of the disclosed steering apparatus 50, controlsystem 60, control techniques, and the like are directed to addressingthese problems.

To do this, the control system 60 seeks to accurately control theactuators (72) for the directional devices (70 a-c) under variousdownhole disturbances, such as stick-slip conditions. Additionally, thecontrol system 60 seeks to be self-calibrating during operations so thata build-up of inaccuracies can be avoided.

Before turning to particulars of the control system 60, discussion firstturns to details related to the various downhole disturbances, such asstick-slip conditions and the like, under consideration. In particular,FIGS. 4A-4B plot examples of stick slip under consideration according tothe present disclosure. These plots 80 and 82 are merely explanatory.

As shown first in the plot 80 of FIG. 4A, stick-slip can cause therotational speed (RPM) of a bottom hole assembly having the disclosedsteering apparatus (50) to oscillate from stick conditions (about 0RPMs) to slip conditions (elevated RPMs), when the torsion built-up inthe drill string during the stick condition releases and the RPM of thebottom hole assembly well exceeds the average RPMs being imparted to thebottom hole assembly for the drilling conditions. As shown, the RPMs canreach above 300 RPM in the slip conditions, and the stick sliposcillations can be cyclical in a more or less uniform fashion when thebottom hole assembly tends to engage roughly the same side of theborehole. Of course, this is not always the case. For example, FIG. 4Bshows the plot 82 of a stick slip condition that is more complex incharacter.

As will be appreciated by one skilled in the art, the slip conditions ofincreased RPM can exceed the resolution of sensing capabilities in agiven control system to an extent that the given control systemincorrectly determines angular orientation. This in turn would lead toincorrect actuation of the apparatus so that the direction of theadvancing borehole would be incorrect. For this reason, the disclosedsteering apparatus 50 has control and sensing capabilities to at leastbetter handle disturbances, such as forms of stick-slip discussedherein.

In addition to stick-slip, high frequency torsional oscillation can beanother downhole disturbance under consideration according to thepresent disclosure. FIGS. 5A-5B plot examples of these types ofoscillations. Again, these plots 85 and 87 are merely explanatory. Asshown first in the plot 85 of FIG. 5A, the RPMs of a bottom holeassembly can oscillate at a high frequency over a short period of timebetween lower and upper RPM values. For instance, one set ofoscillations changes rapidly in a short time period between about 50-RPMto about 225-RPM. A later oscillation changes rapidly in another shorttime period between about 75-RPM to about 250-RPM. Rather than beingdiscrete in time as in FIG. 5A, the high frequency torsionaloscillations can extend over longer periods of time, such as shown inthe plot 87 of FIG. 5B.

Again, as will be appreciated by one skilled in the art, the highfrequency oscillations of RPM can exceed the resolution of sensingcapabilities in a given control system to an extent that the givencontrol system incorrectly determines angular orientation. This in turnwould lead to incorrect actuation of the apparatus so that the directionof the advancing borehole would be incorrect. Again for this reason, thedisclosed steering apparatus 50 has control and sensing capabilities toat least better handle disturbances, such as forms of high frequencytorsional oscillation discussed herein.

To achieve accurate control, for example, the control system 60preferably includes accurate sensors and sensing capabilities. Inparticular, the control system 60 preferably includes an angular rategyroscope sensor (ARG) with a scaled output range between ±2000°/Sec and±5000°/Sec. Moreover, the control system 60 preferably includes anangular position sensor (APS) having magnetic detectors orthogonallyoriented at two-axes and capable of detecting the earth's magneticfield.

The various sensors of the control system 60 have sources of error thatthe control system 60 preferably accounts for to improve accuracy. Forexample, the angular position sensor (APS) of the control system 60 hassources of error that include bias, scale, and misalignment. To improvesensing by the angular position sensor, the bias of the sensor can bedetermined as an average, and compensations based on the average biascan be applied to the angular position readings. Misalignment of how theangular position sensor is installed in the apparatus 50 can beinitially determined and similarly accounted for. The scale of angularposition sensor (APS) is preferably corrected so that the X and Yreadings are scaled for relative comparison to one another.

Because sensing of the tool face has similar errors that include bias,scale, and misalignments, similar accommodations can be made for sensingof the tool face with the control system 60.

The Angular Rate Gyroscope (ARG) of the control system 60 has somewhatdifferent sources of error that include bias and sample period jitter.As before, the bias of the Angular Rate Gyroscope (ARG) is preferablyaccounted for in adjusting the angular rate readings. The sample periodjitter of the Angular Rate Gyroscope (ARG) can be known and applied toreadings as needed.

As a brief example, FIG. 8 plots bias 90 and sensitivity 92 determinedexperimentally for an angular rate sensor (ARG) relative to temperature.In this particular example, the bias 90 of the angular rate sensorremains relative steady from 25 C to about 145 C, but then dropssharply. Sensitivity 92 of the angular rate sensor also remains relativesteady from 25 C to about 145 C, and only rises slowly thereafter. Thecontrol system 60 for the disclosed apparatus 50 can account for suchbias 90 and sensitivity 92 relative to temperature, as in affectssensors such as the angular rate sensor, to improve operation of thesystem 60 during drilling.

Due to such sources of error, the control system 60 preferably performsself-calibration during operations. The form of calibrations at leastinclude angular position and angular rate calibrations. In the angularposition calibration discussed in more detail below, for example, themechanical misalignment of X-Y magnetometers of the control system 60 isapplied to magnetometer readings. Also, corrections for the X-Y rotatingbiases and the X-Y rotating scales are applied to the magnetometerreadings.

In the angular rate calibrations discussed in more detail below, forexample, the bias of an angular rate sensor of the control system 60 isdetermined when pumps (26) are off and the drillstring (22) is notrotating during drillpipe connections. The angular rate readingsobtained during rotations are then corrected for that bias, and anyrotating scale of the readings can be corrected.

With an understanding of the various downhole disturbances, sensingcapabilities, errors, sensitivities, and the like under consideration incontrolling the disclosed apparatus 50, discussion now turns to someparticular details of a control system for the disclosed apparatus 50.In particular, FIG. 6 illustrates a schematic of a control system 100for the disclosed steering apparatus 50. The control system 100 asdepicted here can combine or can be part of one or more previouslydisclosed elements, such as the control assembly 30, control system 60,etc., which are consolidated in the description here. Separate referenceto some of these components may have been made previously in thedisclosure for the sake of simplicity.

The control system 100 includes a processing unit 110 havingprocessor(s), memory, etc. Sensor elements or “sensors” 120, 130, and170 interface with the processing unit 110 and may use one or moreanalog-to-digital converters 140 to do so. In general, the controlsystem 100 uses an angular rate gyroscope to determine an angular rateof the apparatus 50, and readings from a magnetometer give a highside ofthe apparatus 50 for orientation of the apparatus 50 relative to theborehole. For example, various sensor elements can includeinclinometers, magnetometers, accelerometers, and other sensors thatprovide position information to the processing unit 110.

In particular, an inclinometer and azimuthal sensor element 120 caninclude a near-bit azimuthal sensor 122 and a near-bit inclinometersensor 124, which may use magnetometers and Z-axis accelerometers. Astatic toolface sensor 126 can provide the toolface of the apparatus(50) and can have X and Y axes accelerometers. A temperature sensor 128can provide temperature readings. Finally, an angular rate gyroscope(ARG) sensor 130 can provide the angular rate of the apparatus (50)during operation for obtaining position readings.

The processing unit 110 also communicates with an angular positionsensor (APS) 170, which provides static magnetic toolface and detectsthe rotary quadrant of the apparatus (50) during operation. Theprocessing unit 110 can communicate with other components of theapparatus (50) via communication circuitry 112 and a bus and can storeinformation in logging memory 114. Finally, the processing unit 110interfaces with multiple actuator modules 160-1, 160-2, 160-3 of theapparatus (50), which are used to actuate the various directionaldevices as noted herein.

The actuator modules 160-1, 160-2, 160-3 may use sensors 164 to monitorthe operation (e.g., state, position, etc.) of the actuators usingfeedback to the processing unit 110. For example, the sensors 164 can bepressure transducers used to determine the actuators' operations in thefirst instance. The pressure transducers can also provide pressurereadings that can also help determine wear and to verify overalloperation.

During operation, the control system 100 operates based on discreteposition information obtained with the various sensor elements 122, 124,126, 130, 170, etc. The resolution of the position information can be0.5 ms @ 300 rpm, which would can give an angular resolution of about0.9° for the apparatus' rotation. Additionally, the angular rategyroscope sensor 130 is used in conjunction with X-Y crossovers from theAPS 170 to obtain position information at about 3-kHz. The X-Yaccelerometers obtain an offset value of static gravity to magnetichighside for determining toolface of the apparatus (50).

Using a control process discussed below, the processing unit 110processes the input of the various sensor readings and can monitor theoperation (e.g., state, position, etc.) of the actuators using feedbackfrom the modules' sensors 164. In turn, the processing unit 110 providesactuator control signals to the actuator modules 160-1, 160-2, and 160-3to steer the apparatus (50).

FIG. 7 illustrates a flow diagram of a control process 200 used by thecontrol system 100 as in FIG. 6 of the disclosed steering apparatus 50.Overall, starting at acquisition 202, the control process 200 combinesthe operation of the angular position sensor (170), the angular ratesensor (130), and an analog-to-digital converter (140) together todevelop director actuations 290 for the actuator modules (160) based ona target toolface 282. The angular position sensor (170) obtainsmeasurements and is calibrated during rotation in a measurement andcalibration process 270 to produce calibrated magnetometer readings 210.

A toolface offset (TFO) 257 between a magnetic toolface (MTF) 254 and ahighside toolface (HSTF) 256 of the apparatus (50) is determinedperiodically in an offset calculation process 250. The bias 232 of theangular rate sensor (130) is also measured periodically so that the biascorrection 234 can be applied to the readings from the angular ratesensor (130).

Finally, the calibrated magnetometer readings 210 and the calculatedtoolface offset (TFO) 257 are combined in a datum reference calculation220 that is used to re-datum the accumulation of readings from theangular rate sensor (130). In general, the magnetometer(s) for theangular position sensor(s) (170) are used to re-sync the angular ratesensor (ARG) (130) at least one zero crossing point. All position basedcontrol and/or measurements are based upon the calibrated angle providedby the angular rate sensor 130. Ultimately, the accumulated angular ratereadings in an accumulator 236 are used to determine director actuationcalculations 280 based on the target toolface 282 so that the counts ofthe analog-to-digital converter (140) can be properly sampled and theprocessing unit (110) can operate the actuator modules (160) of theapparatus (50).

According to the present disclosure, the angular position measurementsteps 270 may not strictly require “calibrated” magnetometers oraccelerometers to function. Typically, an ArcTan of the measurementsfrom the sensors would be used to compute instantaneous toolface. Assuch, the magnitudes of the measurements involved in the typicalarrangement would be important. However, the process 200 of the presentdisclosure instead uses zero-crossings (see zero-crossing detector 212).Therefore, the magnitudes of the magnetometer and accelerometerwaveforms are of less importance as long as a sufficient signal-to-noiseratio exists for zero-crossing events to be detected. (As an aside, biasand misalignment may still need to be applied to get accuratezero-crossings at the cross points (i.e., 90° points). If themagnetometer misalignment varies between sensors, then this may needcalibration input. That being said, the misalignment could be calculateddynamically.) In the end, an integrated angular rate obtained from thecalibrated angular rate gyroscope sensor 130 fills in the positionalinformation between the zero-crossings 212 to deliver a high-resolutionhybrid angular position system.

Looking first at the measurement and calibration process 270, theangular position sensor (170) obtains magnetometer readings Bx-By. Toaccount for errors due to bias and scale with the angular positionsensor (170), calculations of the X-Y bias 272 and X-Y scale 274 aremade, and a misalignment factor 276 is also applied so that acalibration 278 can be applied. As will be appreciated, the angularposition sensor (170) accumulates rolling errors during rotation so thatthe errors are corrected in the process 270. In correction 272, forinstance, average bias in both X and Y directions is calculated as theapparatus (50) rotates, and the X-Y magnetometer readings of the angularposition sensor (170) are corrected for that average bias. In correction274, the higher amplitude of the magnetometer reading in X or Ydirections is used to scale the lower amplitude reading so that the X-Ymagnetometer readings of the angular position sensor (170) are correctedfor scale. In correction 276, the misalignment is essentially a constantoffset value based on how the X-Y magnetometer of the angular positionsensor (170) is installed in the apparatus (50). With the correctionsapplied in step 278, calibrated X-Y magnetometer readings 210 areproduced.

The calibrated magnetometer readings 210 are fed into a detector 212 todetermine states in X-Y for the datum reference process 220. Here, fourzero-crossing states are determined per each revolution using azero-crossing detector that finds when the sine and cosine signals ofthe X-Y magnetometer readings cross zero, which may simply lend itselfto ready detection. However, any other number of states can bedetermined for any partial revolution or any group of revolutions. Forexample, the number of states can be matched to the number of detectoractuators of the apparatus (50) to simplify later calculations.

Although the angular position sensor (170) may have more than onemagnetometer component used to re-sync the angular rate sensor (ARG)measurement, the system (100) can use a single magnetometer component tore-sync the angular rate sensor (ARG) measurements at zero crossingpoints. Additionally, use of one magnetometer component for the angularposition sensor (170) may not require a misalignment calibration.However, using a single magnetometer component may require a biascalibration to insure that the zero crossings (re-sync points) areproperly spaced (e.g., 180° apart). Yet, if only one zero-crossing perrotation is used for the angular rate sensors' re-sync angle, the biascalibration may not need to be particularly accurate. At most, thesystem (100) may only need to ensure that the magnetometer measurementcrosses zero twice per revolution.

The calibrated magnetometer readings 210 are also fed into the offsetcalculation process 250. As noted above, this process 250 is determinedperiodically when the pumps are off and the apparatus (50) is notrotating, such as when a drill pipe connection is being made at thesurface. Here, the process 250 starts after an initial time (T1) 252 ofthe pumps being off 251. Rotation 253 of the apparatus (50) is checked.If the apparatus (50) is not rotating, then the process 250 calculatesthe magnetic toolface (MTF) 254 using the calibrated magnetometerreadings 210. Because the magnetometer is not rotating, any previous X-Ybias, X-Y scale, and the like determined for the angular position sensor(270) is stored in memory and applied to the calculation of the magnetictoolface (MTF) 254.

The process 250 also calculates the highside toolface (HSTF) 256 usingstatic toolface measurements from accelerometers or the like. These twotoolface readings MTF 254 and HSTF 256 are then used to calculate thetoolface offset 257, which is used to orient the dynamic X-Ymagnetometer readings to a static reference position. The calculatedtoolface offset (TFO) 257 is then fed into the datum reference process220 as an adjustment toolface offset 224 to the dynamic X-Y magnetometerreadings for the magnetic toolface from the angular position sensor(170) during revolutions.

In some instances, this toolface offset (TFO) 257 of the magnetictoolface 254 relative to the highside toolface 256 can be a relativelyconstant value of the drilling distance of one stand of drill pipe. Inother instances, the toolface offset (TFO) 257 can vary as much as15-degrees because the offset 257 may generally depend on theinclination and azimuth of the apparatus (50) while drilling.Accordingly, the calculation of the toolface offset (TFO) 257 may beadjusted by dynamic parameters 258, which may be in the form of constantvalues, variables, and equations based on the inclination and azimuth ofthe apparatus (50) while drilling.

While the pumps are off and the apparatus (50) is not rotating duringthe process 250, the bias 232 of the angular rate sensor (130) is alsomeasured. In general, the measured bias 234 is a relatively stable valueso that evaluating the bias at each drillpipe connection may besufficient.

Alternatively, the angular rate reading bias 232 can be at leastperiodically measured when the apparatus (50) is rotating in theborehole. To do this, the process finds two periods in which averagerotation rates are different. The angular rate gyroscope (ARG) countsand the RPM delta between these two periods can then be used tocalculate a form a scale factor of raw counts per RPM. In other words,from these two period, a ratio is calculated of a count of the angularrate readings relative to a difference in the rotation rates. Theangular rate reading bias can then be determined by linearlyextrapolating the ratio for either of these two periods to a point of norotation (i.e., 0 RPM), which will indicate the bias. (As an aside, itmay be noted that this method of calculating bias while rotatingrequires that the two rotation rates be known so that the zero rotationrate (aka bias) can be linearly extrapolated.) In the end, therequirement to generate each of the two period is similar to the processused to generate a scale factor discussed herein in which an accumulatoris used for ARG counts and an accumulator is used for APS position (seee.g., accumulators 237 a-b).

Ultimately, during acquisition of the angular rate sensor (130), themeasured bias 234 is applied to the angular rate readings from theangular rate sensor (130). The angular rate readings from the angularrate sensor (130) may also go through a dynamic scaling process 235. Asdisclosed herein with reference to FIG. 8, for example, the sensitivityof the angular rate sensor (130) is reduced at the higher temperatures.A dynamic scale factor can be used to extend the operating range of theangular rate sensor (130) and provide for more accurate measurements.This scaling may be done for one or more revolutions based on the zerocrossings as sync points.

Essentially, the process 235 calibrates the readings of the angular ratesensor (130) with the readings of the angular position sensor (170). Inparticular, the process 235 determines a dynamic scale factor to applyto the angular rate measure by using two accumulators 237 a-b andmathematical calculation. A first accumulator 237 a is used to track thetotal number of degrees that the angular position sensor (170) has moved(i.e., “Total Degrees APS”). An additional accumulator 237 b is used totrack the total number of counts from the analog-to-digital converter140 have been gathered from the angular rate sensor (130) (i.e., “TotalARG ADC Counts”). Both accumulators 237 a-b sum over the same period.

Periodically (e.g., based upon degrees traversed), the ARG scale factoris calculated by dividing the “Total Degrees APS” 237 a by the “TotalARG ADC Counts” 237 b. This newly calculated ARG scale factor (degreesper ARG ADC count) can then be used to compensate the ADC counts ofangular rate sensor (130) until a subsequent scale factor is ready. Aswill be appreciated, the dynamic ARG scale factor will be more accuratewhen a larger the number of degrees are traveled for the accumulationand calculation. Notably, the scaling process 235 is not sensitive tostick-slip conditions.

During drilling as the apparatus (50) rotates, the angular rate readingsfrom the angular rate sensor (130) are accumulated in an accumulator236. As will be appreciated, any error in the resolution of the angularrate readings can build significantly over time so that any directionalsteering controls will be in error. Accordingly, the datum referenceprocess 220 uses the calibrated magnetometer readings 210 and thecalculated adjustment toolface offset 224 to calculate seed counts 226of the acquisition for seed angles in the apparatus's rotation. Thecalculation of the seed counts 226 is based on a stored configuration228 for the apparatus (50).

The stored configuration 220 can be preset and can be different asneeded for a given implementation. In general, the configuration 228sets a particular sample period for measurement, dictates the number ofbits for ADC, provides a range and span of RPMs, gives a measurementresolution of RPM relative to count (i.e., degrees of rotation). Exampleinformation for one such configuration 228 is depicted here.

Using the configuration 228, the magnetic toolface states 222 in X-Y,and the adjustment toolface offset 224, the datum reference process 220calculates the seed counts 226 for the various MTF or seed angles, suchas 0, 90, 180, 270-degrees.

The seed counts 226 are then used in processing (i.e., adjusting,re-orienting, etc.) the accumulated angular rate readings in theaccumulator 236 for the director actuations 290 at particular seedcounts (i.e., angles). In this way, the angular rate readings can beseeded in the actuation calculation process 280 for the given targettoolface 282 to advance the borehole in the desired direction.

As shown here, the apparatus (50) in this example has three actuatormodules 160 (i.e., actuators, directors, etc.), although the apparatus(50) may in general having one or more actuators. In this example, theactuators for the modules (160) are arranged uniformly at every120-degrees about the circumference of the apparatus (50), but anyarrangement could be used. In the director actuations 290, the targettoolface 282 (in degrees) is divided into the geometrical arrangement ofthe actuators on the apparatus (50) (i.e., three pistons arrangedsymmetrically about the apparatus' circumference at 120-degress from oneanother). Start 292 of the actuation (shown in degrees/speed counts),stop 294 of the actuation (shown in degrees/speed counts), and width 296of the actuation (shown in degrees/speed counts) are determined for eachof the pads 284 of the actuator module (160) so as to move the apparatus(50) toward the target toolface 282. These actuations 292, 294 are fedto the analog to digital converter 140 in time (T2) 286 so theprocessing unit (110) can operate the actuator modules (160)accordingly. As will be appreciated, the target toolface 282 is providedto the processing unit (110) as part of the drilling operations and maybe dictated from control signals in memory, from telemetry, fromon-board sensing and calculation, etc.

Although discussed for steering during directional drilling as disclosedabove, teachings of the present disclosure can be used in otherimplementations, such as in measurement-while-drilling (MWD) orlogging-while-drilling (LWD) implementations. For instance, theteachings of the present disclosure can be used when measuring/loggingwith at least one sensor on an apparatus in a borehole, either inaddition to or instead of the directional drilling disclosed here.

As briefly shown in FIG. 1, for example, the sensor section 32 of thedownhole assembly 20 can have any type of sensors used inMeasurement-While-Drilling (MWD) and Logging-While-Drilling (LWD)operations including, but not limited to, sensors responsive to gammaradiation, neutron radiation, and electromagnetic fields. In thistechnique, at least one sensor 33 in the sensor section 32 advances inthe borehole 12 while rotation is imparted to the assembly 20.Consequently, the at least one sensor 33 senses measurements whilerotation is imparted to the assembly 20 advancing in the borehole 12.

According to the present technique, angular rate readings are obtainedof the rotation of the assembly 20, and angular position readings areobtained of the assembly 20 during the rotation. The present techniquethen adjusts the angular rate readings based at least on the angularposition readings to determine angular positions of the assembly 20 inthe manner disclosed herein.

In this way, one or more the measurements of the at least one sensor 33sensing during the rotation can be correlated to the determined angularpositions. In turn, an image can be generated using known imaging methodfrom the one or more correlated measurements. The results can give highresolution angular position measurements that can improve the quality oflog images, wellbore surveys, and the like. Also, the correlation canallow for targeted sensing by the at least one sensor 33 of the sensingsection 32. For instance, the one or more measurements sensed with theat least one sensor 33 at one or more sensed directions during therotation can be correlated to one or more targeted directions of thedetermined angular positions. The result is that the at least one sensor33 can sense towards (or be correlated to) the one or more targeteddirections based on the determined angular positions.

The foregoing description of preferred and other embodiments is notintended to limit or restrict the scope or applicability of theinventive concepts conceived of by the Applicants. It will beappreciated with the benefit of the present disclosure that featuresdescribed above in accordance with any embodiment or aspect of thedisclosed subject matter can be utilized, either alone or incombination, with any other described feature, in any other embodimentor aspect of the disclosed subject matter.

In exchange for disclosing the inventive concepts contained herein, theApplicants desire all patent rights afforded by the disclosed subjectmatter. Therefore, it is intended that the disclosed subject matterinclude all modifications and alterations to the full extent that theycome within the scope of the disclosed embodiments or the equivalentsthereof.

What is claimed is:
 1. A method for use with an apparatus in a borehole,the apparatus having at least one element disposed thereon, the methodcomprising: imparting rotation to the apparatus in the borehole about anaxis of the apparatus, the at least one element rotating with theapparatus about the axis during the rotation; obtaining angular ratereadings of the rotation of the apparatus about the axis; obtainingangular position readings of the apparatus about the axis during therotation; determining angular positions of the apparatus about the axisby adjusting the angular rate readings based at least on the angularposition readings; and correlating locations of the at least one elementin the borehole to the determined angular positions about the axisduring the rotation.
 2. The method of claim 1, the at least one elementcomprising at least one measurement sensor disposed on the apparatus,wherein the method further comprises sensing measurements with the atleast one measurement sensor while the rotation about the axis isimparted to the apparatus; and wherein correlating the locations of theat least one element in the borehole to the determined angular positionsabout the axis during the rotation comprises correlating the locationsof the measurements of the at least one measurement sensor in theborehole to the determined angular positions about the axis during therotation.
 3. The method of claim 2, further comprising generating animage of the correlated measurements sensed by the at least onemeasurement sensor.
 4. The method of claim 1, the at least one elementcomprising at least one actuator on the apparatus, wherein correlatingthe locations of the at least one element to the determined angularpositions about the axis during the rotation comprises steering theapparatus in advancing the borehole towards a target direction bydetermining, from the correlated locations of the at least one actuator,actuations of the at least one actuator relative to the target directionand actuating the at least one actuator during the rotation based on thedetermined actuations.
 5. A method of drilling a borehole with anapparatus having at least one actuator disposed thereon, the methodcomprising: advancing the borehole by imparting rotation to theapparatus about an axis; obtaining angular rate readings of the rotationof the apparatus about the axis; obtaining angular position readings ofthe apparatus during the rotation; and steering the apparatus in theadvancing borehole towards a target direction by: determining angularpositions of the apparatus about the axis by adjusting the angular ratereadings based at least on the angular position readings; and directingthe apparatus towards the target direction by actuating the at least oneactuator during the rotation relative to the determined angularpositions.
 6. The method of claim 5, wherein obtaining the angular ratereadings comprises obtaining the angular rate readings using an angularrate gyroscope disposed on the apparatus; and wherein obtaining theangular position readings comprises obtaining the angular positionreadings using magnetometers disposed on the apparatus and orientedorthogonally in two-axes.
 7. The method of claim 5, further comprising:obtaining at least periodically toolface offset readings of theapparatus in the borehole when not rotating; and correcting the angularposition readings of the apparatus relative to the at least periodicallyobtained toolface offset readings, wherein adjusting the angular ratereadings comprises adjusting the angular rate readings based at least onthe angular position readings corrected relative to the at leastperiodically obtained toolface offset readings.
 8. The method of claim7, wherein obtaining at least periodically the toolface offset readingsof the apparatus in the borehole when not rotating comprises:determining that the apparatus is not rotating; determining a magnetictoolface of the apparatus when not rotating; determining a highsidetoolface of the apparatus when not rotating; and calculating thetoolface offset from the determined magnetic toolface and highside toolface.
 9. The method of claim 8, wherein determining the magnetictoolface comprises obtaining X-Y magnetometer readings; and whereindetermining the highside tool face comprises obtaining accelerometerreadings.
 10. The method of claim 8, further comprising adjusting thecalculated toolface offset by at least one dynamic parameter based oninformation of inclination and azimuth of the apparatus.
 11. The methodof claim 5, wherein obtaining the angular position readings of theapparatus during the rotation comprises calculating, for each of one ormore states of the angular position readings in one or more orthogonalaxes, a resolved angular orientation corrected by a toolface offset. 12.The method of claim 11, wherein the one or more orthogonal axescomprises X-Y directions; and wherein calculating comprises detectingzero-crossings for the X-Y directions of the angular position readingsat four of the states in each of the X-Y directions.
 13. The method ofclaim 12, wherein adjusting the angular rate readings based at least onthe angular position readings comprises adjusting the angular ratereadings accumulated over time by the resolved angular orientations. 14.The method of claim 5, further comprising: measuring angular ratereading bias at least periodically; and adjusting the angular ratereadings obtained during the rotation by the at least periodicallymeasured bias.
 15. The method of claim 14, wherein measuring the angularrate reading bias at least periodically comprises measuring the angularrate reading bias at least periodically when the apparatus is rotatingin the borehole; and wherein adjusting the angular rate readingsobtained during the rotation by the at least periodically measured biascomprises: finding at least two periods in which average rotation ratesare different; calculating, from the at least two periods, a ratio of acount of the angular rate readings relative to a difference in therotation rates; and determining the angular rate reading bias bylinearly extrapolating the ratio for at least one of the periods to apoint of no rotation.
 16. The method of claim 5, further comprisingcalibrating the angular position readings obtained during the rotationbased on at least one of: sensor bias, scale of first of the readingswith respect to a first axis relative to second of the readings withrespect to a second axis, a misalignment of the first and second axesrelative the apparatus; and temperature effects based on a scale factordetermined dynamically from the obtained angular position readings. 17.The method of claim 5, wherein directing the apparatus towards thetarget direction by actuating the at least one actuator during therotation relative to the determined angular positions comprises using apoint-the-bit configuration or a push-the-bit configuration of the atleast one actuator.
 18. An apparatus used in a borehole, the apparatuscomprising: at least one element disposed on the apparatus and rotatingtherewith about an axis of the apparatus during rotation in theborehole; a sensing element obtaining angular position readings duringthe rotation and obtaining angular rate readings of the rotation; and acontrol system in operable communication with the at least one elementand the sensing element, the control system configured to: adjust theangular rate readings based at least on the angular position readings todetermine angular positions of the apparatus about the axis; andcorrelate locations of the at least one element to the determinedangular positions about the axis during the rotation.
 19. The apparatusof claim 18, wherein the at least one element comprises at least onemeasurement sensor disposed on the apparatus and sensing measurementswhile the rotation about the axis is imparted to the apparatus; andwherein to correlate the locations of the at least one element to thedetermined angular positions about the axis during the rotation, thecontrol system is configured to correlate the measurements of the atleast one measurement sensor to the determined angular positions aboutthe axis during the rotation.
 20. The apparatus of claim 18, wherein theat least one element comprises at least one actuator disposed on theapparatus and being operable to steer the apparatus in advancing theborehole towards a target direction; and wherein to correlate thelocations of the at least one element to the determined angularpositions about the axis during the rotation, the control system isconfigured to: determine, from the correlated locations of the at leastone actuator, actuations of the at least one actuator relative to thetarget direction, and actuate the at least one actuator during therotation based on the determined actuations.